Cryogenic liquefaction is commonly used to convert natural gas into a more convenient form for transportation and/or storage. Because liquefying natural gas greatly reduces its specific volume, large quantities of natural gas can be economically transported and/or stored in liquefied form.
Transporting natural gas in its liquefied form can effectively link a natural gas source with a distant market when the source and market are not connected by a pipeline. This situation commonly arises when the source of natural gas and the market for the natural gas are separated by large bodies of water. In such cases, liquefied natural gas (LNG) can be transported from the source to the market using specially designed ocean-going LNG tankers.
Storing natural gas in its liquefied form can help balance periodic fluctuations in natural gas supply and demand. In particular, LNG can be “stockpiled” for use when natural gas demand is low and/or supply is high. As a result, future demand peaks can be met with LNG from storage, which can be vaporized as demand requires.
Several methods exist for liquefying natural gas. Some methods produce a pressurized LNG (PLNG) product that is useful, but requires expensive pressure-containing vessels for storage and transportation. Other methods produce an LNG product having a pressure at or near atmospheric pressure. In general, these non-pressurized LNG production methods involve cooling a natural gas stream through indirect heat exchange with one or more refrigerants and then expanding the cooled natural gas stream to near atmospheric pressure. In addition, most LNG facilities employ one or more systems to remove contaminants (e.g., water, mercury and mercury components, acid gases, and nitrogen, as well as a portion of ethane and heavier components) from the natural gas stream at different points during the liquefaction process.
In general, LNG facilities are designed and operated to provide LNG to a single market in a specific region of the world. Because specifications for the final characteristics of the natural gas product, such as, for example, higher heating value (HHV), Wobbe index, methane content, ethane content, C3+ content, and inerts content vary widely throughout the world, LNG facilities are typically optimized to meet a certain set of specifications for a single market. In large part, achieving the stringent final product specifications involves effectively removing certain components from the natural gas feed stream.
One or more heat exchangers involved in the liquefaction process may be configured as core-in-shell heat exchangers that include one or more cores. In addition, when the LNG processing is done off shore, baffles are used between cores of the heat exchanger to address the sloshing of the shell-side liquid (refrigerant). Because the baffles cause a pressure gradient or horizontal pressure drop across the shell, the single drain configuration results in unequal refrigerant levels at different parts (related to different cores) of the heat exchanger. Unequal refrigerant levels can cause several problems. In a core in which the shell-side liquid level is too high (for example, because the core is farthest from the drain), efficient heat exchange, in the form of boiling of the refrigerant, may be suppressed. In a core in which the shell-side liquid level is too low, the core may not be in contact with the refrigerant and, as a result, heat exchange may not take place at all. The discussion of FIG. 2 below illustrates some of the issues that arise from the prior drain configuration.
FIG. 2 is a block diagram of a core-in-shell heat exchanger 200 according to the prior art. FIG. 2 illustrates the prior approach to draining the shell. The heat exchanger 200 is assumed to be in an off-shore environment, for example, where baffles 1 are used to reduce sloshing of the shell-side fluid (refrigerant). The heat exchanger 200 includes three cores 2 with baffles 1 on either side of each core 2. A weir plate 3 is used to separate the cores from the drain which includes a vortex breaker 4 that minimizes entrained vapor flow into the outlet drain line 5. The baffles 1 are designed to create additional flow resistance within the heat exchanger 200 and dampen the effects of motion to prevent wave action building in the heat exchanger 200, because the wave action could cause liquid to flood over the top of a core 2 or low liquid levels in a core 2 or liquid levels falling beneath a core 2. However, Computational Fluid Dynamics (CFD) analysis, static calculations, and scale model testing have demonstrated that the pressure drop across the baffles 1 required to satisfactorily suppress the liquid motion results in excessive liquid stack-up and flooding in the core 2 located farthest from the weir plate 3. In addition, the core 2 located closest to the weir plate 3 experiences low liquid levels. Due to the resistance to liquid flow caused by the baffles 1, the liquid level in the outflow section experiences low enough liquid level that there is a high potential for gas ingestion into the liquid drain. This gas ingestion is a serious operational constraint and will severely restrict the downstream process equipment capacity and operation. That is, the variations in the liquid level resulting from the baffles 1 can have a deleterious effect on the thermal performance of the heat exchanger 200 and on the mechanical integrity of the heat exchanger 200 due to thermally induced fatigue stress which can shorten the life of the heat exchanger 200 and result in damage and a leaking heat exchanger 200.